Primary production refers to hydrocarbons (e.g., oil and gas) that is recovered naturally from a producing well. Enhanced Oil Recovery (EOR) refers to recovery operations that improve the amount of hydrocarbons recovered from a well. One form of EOR is water injection. Water injection refers to the operation of injecting water into a hydrocarbon reservoir, usually to increase pressure and thereby stimulate production. The water used for water injection is often a brine or other suitable water based fluid that is treated. For example, in some reservoirs water is produced with the hydrocarbons via a production well, removed from the production well and re-injected into the formation. In some instances, water injection is accomplished via an injection well to stimulate hydrocarbon production in a separate production well. For example, a production field may include a production well and a water injection well located some distance from one another. The injection well may include a well drilled specifically for injection operations, or may simply include a production well that has been repurposed for injection operations. Water is injected into the water injection well to increase the pressure in the formation, thereby urging the hydrocarbons to flow through the reservoir formation toward and into the production well. This can aid in extracting hydrocarbons from the reservoir that may otherwise not be recovered.
During a water injection operation for an oil reservoir, water is injected into the reservoir through one or more injection wells in an effort to maintain prescribed reservoir pressures while production wells produce oil from the reservoirs. The injected water enters the permeable sections of the reservoir to fill in the voids created by the evacuation of produced oil, maintaining pressure within the reservoir. As the water moves through the reservoir, it displaces oil and urges the displaced oil towards the producing wells, aiding in effective recovery of the oil from the reservoir. In some instances, the cumulative volume of injected water can be approximately equal to, or slightly higher than, the cumulative oil volume produced from the reservoir. Unfortunately, although the injected water is typically treated in a treatment plant before being injected into the target reservoir, the injected water can sometimes contain fine-suspended solids that can become trapped in the formation of the reservoir. The quality of water received at the wellhead of a water injection well can be adversely affected, for example, by bacterial contamination of shipping lines, biocide batch treatments, line scrapings and the like. Over time the solids trapped in the formation can reduce the permeability of the formation of the reservoir by blocking flow paths of the water through the reservoir. This blockage type of reservoir damage is sometimes referred to as formation plugging. Formation plugging can occur on the face of the formation at the wellbore (e.g., forming a “filter cake” at or near the walls of the wellbore) or deep in the reservoir, within a few inches to few feet of the wellbore. The plugging increases the resistance along the flow path of the water through the formation of the reservoir. The innovative techniques described herein are effective for damage at any depth.
In some instances, an injection well can have a prescribed injection rate determined, for example, based on oil production rates for adjacent production wells. Over time, in an effort to maintain the injection rate for the well, the injection pressure for the well may be increased to overcome the additional resistance attributable to the plugging along the flow path of water. If the injection pressure is too high, however, it can exceed the formation fracture pressure, and induce fractures in the rock formations around the injection well. These formation fractures can, in turn, can provide additional pathways that allow fine-suspended solids in the injected water to travel further into the formation of the reservoir, causing increased damage to deeper sections of the reservoir. Further, such damages are counterproductive to oilfield operations as they can require excessive pumping power, threaten the longevity of flowlines and hardware, and reduce the overall water injection rate and volume. In some instances, well stimulation operations can be employed to remediate the damages. However, it can be more difficult to remediate damages located deeper in the formation of a reservoir, farther from the wellbore.
Transient-pressure tests, also known as well tests, are often performed on wells, including water injection wells, to evaluate performance of individual wells and reservoir characteristics. Well tests can include periodic tests that are conducted on producing oil wells and injecting water wells to acquire certain information about their productivity and injectivity, respectively, and to characterize the in-situ properties of the near-wellbore reservoir regions. Properties derived from such well tests can be important in evaluating the reservoir productivity and injectivity, and accessibility to a reservoir's hydrocarbon reserves, in addition to the ability to understand and characterize reservoir rocks and their dynamic behaviors under in-situ conditions. In typical well test operations, pressure and production or injection rates are measured as functions of time, usually using high-resolution pressure gauges located at surface or downhole. The pressure responses can be analyzed and interpreted by identifying flow regimes using appropriate well and reservoir models. Analyses of the data obtained from well tests, often called pressure-transient analyses, can be used to determine various characteristics, such as reservoir permeability, mobility, formation damage parameter in terms of skin factors, reservoir pressure, reservoir size and shape, and locations of main geological features or boundaries. As recognized by Applicants, such well tests of a reservoir may be negatively affected by damages to the formation of the reservoir.